An energy management system (hereinafter referred to as EMS) is a computer-based control automation system of a modern power system, an aim of which is to perform real-time collecting, monitoring, analyzing, optimization and control decisions for the power system. A power system state estimation is a foundation and a key issue of EMS, which eliminates error information using real-time measurement information collected from the power system and performs calculation to obtain a complete, consistent and reliable power system real-time variable so as to ensure an accuracy of an EMS control decision.
A conventional state estimation is implemented in a power control center, uses a remote terminal unit (hereinafter referred to as RTU) to collect analog and digital raw data, and sends the analog and digital raw data to the control center through a supervisory control and data acquisition system (hereinafter referred to as SCADA), thus completing the whole grid topology analysis and state estimation. Since information sent to the control center is not sufficient, an accuracy of control center automation basic data may not be satisfying by improving conventional state estimation model and algorithm, and an unavailability of a centralized state estimation resulted from topology errors, non-linear iteration divergence, big errors, etc. has become a bottleneck in a practicability of a worldwide control center advanced application. A fundamental reason for the above problem lies in irrational information distribution and processing. On the one hand, the information in the control center is centralized very much. An establishment of a whole grid model (comprising equipment parameters, static topology, and a single-line diagram) needs to be completed in the control center, and consequently a workload is significantly increasing with an increase of a grid size. Meanwhile, maintenance personnel in the control center may not be very familiar with every detail of the grid, a potential error may occur highly likely, and parameter errors or topology errors will be buried in large grid model information and may be difficult to remove. On the other hand, the information in a local control center may not be redundant enough. In order to avoid vast amounts of information transmission and storage, a part of information most concerned by the control center is usually sent by a substation, so that the control center may not obtain the redundant measurement information in the substation. Due to insufficient measurement redundancy, topology error and bad data detection and identification have become a difficult problem troubling the control center for many years. In addition, once the centralized control center suffers a disaster, paralysis of all the functions may be easily caused and may be difficult to heal.
A PMU (phasor measurement unit)-based substation-control center two-level distributed linear state estimation method is provided. Firstly a local linear state estimation is performed using PMU, and analog bad data and topology errors are identified simultaneously to obtain ripe data. Then, the ripe data are sent to the control center through a communication network to achieve a whole-grid linear state estimation. This method effectively improves a reliability of a whole-grid state estimation, particularly, a capability of the topology error detection. However, this method only uses the PMU measurements to perform a linear state estimation, and consequently it may apply only to a substation equipped with the PMU, but may not apply to a vast majority of substations without the PMU. Even for the substation equipped with the PMU, because RTU measurements are not used, the measurement redundancy and the ability to identify measurement errors may be reduced. At the same time, the network structure has been simplified, it is assumed that a system is running under a three-phase balance condition, a single-phase state estimation is performed in the substation and a result of the single-phase state estimation is sent to the control center, and the control center may not monitor a three-phase unbalance degree and a non-three-phase operating condition of the grid.